The embodiments described herein relate to sag in wellbore fluids.
Wellbore fluids often include a plurality of particles that impart specific properties (e.g., viscosity, mud weight (or density), and the like) and capabilities (e.g., wellbore strengthening) to the wellbore fluid. It should be understood that the terms “particle” and “particulate,” as used in this disclosure, includes all known shapes of materials, including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials), and combinations thereof.
In drilling fluids, for example, weighting agents (i.e., particles having a specific gravity greater than the base fluid of the drilling fluid) can be used to produce drilling fluids with the desired mud weight (i.e., density), which affects the equivalent circulating density (“ECD”) of the drilling fluid. During drilling operations, for example, the ECD is often carefully monitored and controlled relative to the fracture gradient of the subterranean formation. Typically, the ECD during drilling is close to the fracture gradient without exceeding it. When the ECD exceeds the fracture gradient, a fracture may form in the subterranean formation and drilling fluid may be lost into the subterranean formation (often referred to as lost circulation). In another example, lost circulation materials (“LCMs”) can be used to strengthen the wellbore and increase the hoop stress around the wellbore, which allows for a higher ECD. The LCMs incorporate into and plug microfractures extending from the wellbore, so as to mitigate fracture propagation and lost circulation.
As used herein, the term “sag” refers to an inhomogeneity or gradation in particle distribution in the fluid as a result of the particles settling (e.g., under the influence of gravity or secondary flow). When sag is observed with weighting agents, the density of the fluid is inhomogeneous or graded.
Oftentimes in a wellbore operation, the circulation of the wellbore fluids through the drill string and wellbore is halted such that the wellbore fluid becomes substantially static in the wellbore (e.g., drill string tripping). In some instances, low shear conditions may be result from slowing circulation or halting circulation while rotating the drill string. As used herein, the term “low shear” refers to a circulation rate with an annular velocity less than about 10 ft/min or a drill string rotation rate of less than 10 rpm. Static or low shear wellbore fluids may allow the particles to settle (i.e., sag). Sag may not occur throughout an entire wellbore, but its occurrence in even a small section of the wellbore can cause well control issues like kicks, lost circulation, stuck pipes, wellbore collapse, and possibly a blowout. For example, if the density of the wellbore fluid, and consequently hydrostatic pressure, are higher than the fracture gradient of the formation, the formation may fracture and cause a lost circulation well control issue. In another example, sag may lead to a portion of the wellbore fluid having a sufficiently high density for a pipe to get stuck therein. Unsticking the pipe can, in some instances, cease the wellbore operation and require expensive and time consuming methods. In yet another example, large density variations in a sagging wellbore fluid may result in wellbore collapse. In another example, the lower density portion of the sagged fluid may, in some instances, readily flow when circulation is resumed or increased and leave the higher density portion of the fluid in place, which is time consuming and expensive to remove. Each of these well control issues and potential remediation are expensive and time consuming.
Sag in wellbore fluids is exacerbated by higher temperatures and deviation in the wellbore. Therefore, the recent strides in extended reach drilling, which have resulted in highly deviated wellbores at greater depths where temperatures can be greater, increase the concern for and possible instances of sag related problems in the oil and gas industry.